During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. During this circulation, a wellbore fluid may act to remove drill cuttings from the bottom of the hole to the surface, to suspend cuttings and weighting material when circulation is interrupted, to control subsurface pressures, to maintain the integrity of the wellbore until the well section is cased and cemented, to isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore, to cool and lubricate the drill string and bit, and/or to maximize penetration rate.
Another wellbore fluid used in the wellbore following the drilling operation is a completion fluid. Completion fluids broadly refer any fluid pumped down a well after drilling operations have been completed, including fluids introduced during acidizing, perforating, fracturing, workover operations, etc. A drill-in fluid is a specific type of wellbore fluid that is designed to drill and complete the reservoir section of a well in an open hole, i.e., the “producing” part of the formation. Such fluids are designed to balance the needs of the reservoir with drilling and completion processes. In particular, it is desirable to protect the formation from damage and fluid loss, and not impede future production. Most drill-in fluids contain several solid materials including viscosifiers, drill solids, and additives used as bridging agents to prevent lost circulation and as barite weighting material to control pressure formation.
A further application for wellbore fluids include annular fluids or packer fluids which are pumped into an annular opening between a casing and a wellbore wall or between adjacent, concentric strings of pipe extending into a wellbore. In the completion of oil and gas wells, it is currently the practice to place aqueous or non-aqueous hydrocarbon based fluids, known as packer fluids, into a casing annulus above a packer, specifically where the packer has been set to isolate production fluid from the casing annulus. Packer fluids, introduced into the casing annulus, fill the annular column to surface. Packer fluids are used to provide both pressure stability and thermal protection to the casing annulus of production oil and gas wells as well as in injection wells. The main function of a packer fluid related to pressure stabilization is to provide hydrostatic pressure in order to equalize pressure relative to the formation, to lower pressures across sealing elements or packers; or to limit differential pressure acting on the well bore, casing and production tubing to prevent collapse of the wellbore.
Wellbore fluid compositions are known to be flowable systems that are generally thickened to a limited extent. In many cases, wellbore fluids may include thickening agents such as polymers or viscoelastic surfactants, which serve to control the viscosity of the fluids. To obtain the fluid characteristics required to meet these challenges, the fluid may be easy to pump so only a small amount of pressure is required to force it through restrictions in the circulating fluid system, such as bit nozzles, down-hole tools, or narrow wellbore annuli. In other words, the fluid may have the lowest possible viscosity under high shear conditions. Conversely, in zones of the well where the area for fluid flow is large and the velocity of the fluid is slow or where there are low shear conditions, the viscosity of the fluid may be great enough to suspend and transport the drilled cuttings. The need for a sufficient viscosity also applies to the periods when the fluid is left static in the hole, where both cuttings and weighting materials need to be kept suspended to prevent settlement.
Viscoelastic surfactants are commonly used as thickening agents. Viscoelastic surfactants may be relatively small molecules with each molecule being less than 500 grams per mole (i.e., molecular weight less than 500). The individual molecules of surfactant begin to associate to form rod-like or spiraling-cylinder-like micelles or other micellar structures. These micelle structures are always in an equilibrium state of breaking and reforming. As dynamic structures, micelles are readily destroyed by shear, presence of hydrocarbons or increased temperature. While these features are desirable especially in a hydrocarbon-bearing formation, there is minimal control over the conditions under which micelle breakup occurs. Therefore, under conditions of exposure to oil, high temperature, high shear, or other “stress conditions”, the viscoelastic surfactants rapidly return to their original small independent spherical micellar state. When the viscoelastic micelles are broken down to this small independent spherical micellar state, the desired viscous nature of the well fluid is lost. In some cases the loss is temporary, in others the loss may be more permanent.
Accordingly, there exists a continuing need to improve viscosification of wellbore fluids using viscoelastic surfactant compositions.